Crude oil development and production from oil bearing formations can include up to three phases: primary, secondary and tertiary (or enhanced) recovery. During primary recovery, the natural energy present in the formation (e.g., water, gas) and/or gravity drives oil into the production wellbore. As oil is produced from an oil bearing formation, pressures and/or temperatures within the formation may decline. Artificial lift techniques (such as pumps) may be used to bring the oil to the surface. Only about 10 percent of a reservoir's original oil in place (OOIP) is typically produced during primary recovery. Secondary recovery techniques are employed to extend the field's productive life and generally include injecting a displacing fluid such as water (waterflooding) to displace oil and drive it to a production wellbore.
Secondary recovery techniques typically result in the recovery of an additional 20 to 40 percent of a reservoir's OOIP. However, even if waterflooding were continued indefinitely, typically more than half of the OOIP would remain unrecovered. Poor mixing efficiency between water and oil (because of high interfacial tension between the water and oil), capillary forces in the formation, the temperature of the formation, the salinity of the water in the formation, the composition of the oil in the formation, poor sweep of the injected water through the formation, and other factors contribute to the inefficiency. Primary and secondary techniques therefore leave a significant amount of oil in the reservoir.
With much of the easy-to-produce oil already recovered from oil fields, producers have employed tertiary, or enhanced oil recovery (EOR), techniques that offer potential for recovering 30 to 60 percent or more of a reservoir's OOIP. Three major categories of EOR have succeeded commercially: thermal recovery, gas injection, and chemical techniques. Thermal recovery introduces heat (e.g., injection of steam) to lower the viscosity of the crude oil to improve its ability to flow through the reservoir. Gas injection uses nitrogen, carbon dioxide, or other gases that expand in a reservoir to push additional oil to a production wellbore. Other gases dissolve in the oil to lower its viscosity and improve its flowability. Chemical techniques inject surfactants (surfactant flooding) to reduce the interfacial tension that prevents or inhibits oil droplets from moving through a reservoir or inject polymers that allow the oil present in the formation to more easily mobilize through the formation.
Chemical techniques can be used before, during, or after implementing primary and/or secondary recovery techniques. Chemical techniques can also complement other EOR techniques. Surfactant flooding includes surfactant polymer (SP) flooding and alkali surfactant polymer (ASP) flooding. In SP flooding, a reservoir is injected with water and/or brine containing ˜1 wt. % surfactant and ˜0.1 wt. % polymer. ASP flooding includes alkali in addition to the components used in SP flooding. ASP systems typically contain ˜0.5 to 1 wt. % alkali, ˜0.1 to 1 wt. % surfactant, and ˜0.1 to 1 wt. % polymer. Typically, an SP or ASP flood is followed up with an injection of a displacing fluid, e.g., a waterflood and/or polymer “push” fluid. The choice between SP or ASP depends on the acid value of the oil to be recovered, the concentration of divalent cations in the reservoir's brine, the economics of the project, the ability to perform water softening or desalination, and other factors. Alkali sequesters divalent cations in the formation brine and thereby reduces the adsorption of the surfactant during displacement through the formation. Alkali also generates an anionic surfactant (sodium naphthenate soap) in situ in the formation by reacting with naphthenic acids that are naturally present in the crude oil. The use of relatively inexpensive alkali reduces the surfactant retention and hence reduces the amount of surfactant required, and therefore also reduces the overall cost. Alkali can also help alter formation wettability to a more water-wet state to improve the imbibition rate.
In “wettability alteration,” another EOR technique, surfactants are introduced into a reservoir, sometimes combined with altering electrolyte concentration, to displace adsorbed oil by effecting spontaneous imbibition of water onto the reservoir rock. This technique does not necessarily require low interfacial tensions between the oil and aqueous phases or the formation of a microemulsion phase. It also does not require a good sweep efficiency of the displacing fluid, and as such could have utility in carbonate reservoirs which can be fractured and typically have poor conformance. Surfactants used in SP and ASP floods have also displayed utility in wettability alteration.
A surfactant system, after injection into an oil bearing formation, takes up crude oil and brine from the formation to form a multiphase microemulsion in situ. When complete, the microemulsion is immiscible with the reservoir crude and exhibits low interfacial tension (IFT) with the crude oil and brine. Commercial surfactant EOR processes achieve ultra-low IFTs (i.e., less than 10−2 mN/m) to mobilize disconnected crude oil droplets in the formation and create an oil bank where both oil and water flow as continuous phases. IFT changes with salinity, surfactant composition, crude oil composition, formation temperature, and other variables. For anionic surfactants, an optimal salinity exists at which the microemulsion solubilizes equal volumes of oil and water, and at which the microemulsion exhibits nearly equal IFTs with oil and brine. The ultra-low IFT generally exists only in a narrow salinity range that overlaps the optimal salinity for a given microemulsion.
As explained by P. Zhao et al. (“Development of High-Performance Surfactants for Difficult Oils,” SPE/DOE Improved Oil Recovery Symposium, Tulsa, Okla., April 2008, SPE 113432), the “selection of surfactants for enhanced oil recovery applications requires laboratory testing with crude oil from the target reservoir and may involve considerable effort to find a suitable surfactant and other . . . components . . . such as polymer, electrolytes, co-surfactant and co-solvent.”
Anionic surfactants used in EOR applications have included alkyl aryl sulfonates (AAS), α-olefin sulfonates (AOS), internal olefin sulfonates (IOS), alcohol ether sulfates derived from propoxylated C12-C20 alcohols, and mixtures thereof. The sulfonates are usually made by reacting an alkylate, α-olefin, or internal olefin with sulfur trioxide in the presence of an inert gas, followed by neutralization. Internal olefin sulfonates uniquely have a polar head and two non-polar tails. Recently, it was reported that IOS derived from internal olefins having a high proportion of 1,2-disubstitution impart performance advantages for EOR applications (see U.S. Pat. Appl. Publ. No. 2010/0282467). In particular, it was found that optimal salinities of microemulsions made from sulfonates derived from internal olefins containing low amounts of trisubstituted olefins are significantly lower than optimal salinities of microemulsions made from sulfonates derived from internal olefins of the same carbon length that contain appreciable amounts of trisubstituted olefins. Internal olefins with high 1,2-disubstitution are conveniently available from metathesis of α-olefin-containing feedstocks, while other internal olefins can be produced by olefin oligomerization, Fischer-Tropsch processes, catalytic dehydrogenation, thermal cracking, and other known processes.
EOR compositions have been made by combining IOS with a nonionic surfactant such as an ethoxylated alcohol or mixtures of an alcohol and an ethoxylated alcohol (see U.S. Pat. Appl. Publ. No. 2009/0203557). According to the '557 publication, a relatively high proportion of the nonionic surfactant (up to 25% based on the amount of IOS used) may be needed to justify its injection into a reservoir. The reference does not suggest combining internal olefin sulfonates with sulfated ethoxylated alcohols or other anionic surfactants.
Among many possible combinations of surfactants, a mixture of an IOS derived from a C15-C18 olefin and an ether sulfate derived from a propoxylated C16-C17 alcohol has shown promise in West Texas dolomite core flooding experiments (see D. Levitt et al., “Identification and Evaluation of High Performance EOR Surfactants,” SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Okla., April 2006, SPE 100089). The authors investigated propoxylated materials having 3, 5, or 7 PO units per molecule, particularly 7 PO units (see Tables 1 and 2 on p. 7 of the Levitt paper). Typically, about a 3:1 weight ratio of propoxylated C16-C17 alcohol sulfate to C15-C18 IOS was used. The authors favored a formulation containing this surfactant blend and 2 wt. % of sec-butyl alcohol as a cosolvent because it exhibited a high solubilization ratio at optimal conditions. When the sec-butyl alcohol was omitted or reduced to 0.5 wt. %, however, the microemulsion was viscous and an optimum solubilization ratio could not be determined (see Table 2). Use of a cosolvent is a common tactic for avoiding high-viscosity or gel-phase microemulsions, broadening the range over which desirably low IFTs are obtained, and/or improving aqueous stability of the chemical components. Although this makes the formulation more robust for field implementation, cosolvents can make the formulation expensive, so their use is preferably avoided or at least minimized.
The EOR industry benefits from identification of new surfactants or surfactant combinations with performance advantages. In particular, surfactants that can promote a low interfacial tension between aqueous and hydrocarbon phases in geologic formations are highly desirable. Also valuable are surfactants that can generate stable, low-viscosity microemulsions with viscous oils, particularly in the absence of turbulent flow conditions. Ideally, good performance could be achieved with reduced reliance on cosolvents, which add considerably to formulation cost.